Wellbore Conditioning System

ABSTRACT

A wellbore conditioning system is disclosed. The system comprises at least one shaft and at least two eccentric unilateral reamers, wherein the unilateral reamers are positioned at a predetermined distance from each other and the unilateral reamers are positioned at a predetermined rotational angle from each other.

REFERENCE TO RELATED APPLICATIONS

This application claims priority to provisional applications U.S.Provisional Application Ser. No. 61/542,601, filed Oct. 3, 2011, andU.S. Provisional Application Ser. No. 61/566,079, filed Dec. 2, 2011,both entitled “Wellbore Conditioning System,” both of which arespecifically and entirely incorporated by reference.

BACKGROUND

1. Field of the Invention

The invention is directed to wellbore conditioning systems and devices.In particular, the invention is directed to systems and devices forconditioning horizontal wellbores.

2. Background of the Invention

Drill bits for drilling oil, gas, and geothermal wells, and othersimilar uses typically comprise a solid metal or composite matrix-typemetal body having a lower cutting face region and an upper shank regionfor connection to the bottom hole assembly of a drill string formed ofconventional jointed tubular members which are then rotated as a singleunit by a rotary table or top drive drilling rig, or by a downhole motorselectively in combination with the surface equipment. Alternatively,rotary drill bits may be attached to a bottom hole assembly, including adownhole motor assembly, which is, in turn, connected to a drill stringwherein the downhole motor assembly rotates the drill bit. The bit bodymay have one or more internal passages for introducing drilling fluid,or mud, to the cutting face of the drill bit to cool cutters providedthereon and to facilitate formation chip and formation fines removal.The sides of the drill bit typically may include a plurality of radiallyor laterally extending blades that have an outermost surface of asubstantially constant diameter and generally parallel to the centrallongitudinal axis of the drill bit, commonly known as gage pads. Thegage pads generally contact the wall of the borehole being drilled inorder to support and provide guidance to the drill bit as it advancesalong a desired cutting path or trajectory.

During the drilling of horizontal oil and gas wells, for example, thetrajectory of the wellbore is often uneven and erratic. The hightortuosity of a wellbore, brought about from geo-steering, directionaldrilling over corrections, and/or formation interaction, makes runningmulti stage expandable packer assembles or casing in such wellsextremely difficult and sometimes impossible. While drilling long reachhorizontal wells, the friction generated from the drill string andwellbore interaction severely limits the weight transfer to the drillbit, thus lowering the rate of penetration and potentially causingnumerous other issues and, in a worst case scenario, the inability toreach the total planned depth of the well.

Currently the majority of hole enlargement tools have either a straightmechanical engagement or hydraulic engagement. These tools have hadseveral reliability issues, including: premature engagement, not openingto their desired position, and not closing fully, all of which can leadto disastrous results. Such tools include expandable bits, expandablehole openers, and expandable stabilizers. The use of conventional fixedconcentric stabilizers and reaming-while-drilling tools have also provento be ineffective in most cases.

SUMMARY OF THE INVENTION

The present invention overcomes the problems and disadvantagesassociated with current strategies and designs and provides new toolsand methods of conditioning wellbores.

An embodiment of the invention is directed to a wellbore conditioningsystem. The system comprises at least one shaft and at least twounilateral reamers extending from the at least one shaft. The unilateralreamers are positioned at a predetermined distance from each other andthe unilateral reamers are positioned at a predetermined rotationalangle from each other.

Preferably, each unilateral reamer extends from an outer surface of theat least one shaft in a direction perpendicular to the axis of rotationof the shaft. In the preferred embodiment, each reamer is comprised of aplurality of blades, wherein each blade has a larger radius than aprevious blade in the direction of counter rotation. The systempreferably further comprises a plurality of cutters coupled to eachblade. Each cutter is preferably a Polycrystalline Diamond Compact (PDC)cutter. The system also preferably further comprises at least one domeslider coupled to each blade. Preferably, each dome slider is a PDC domeslider.

Preferably, there is a recess in the at least one shaft adjacent to eachreamer. In the preferred embodiment, the at least one shaft and reamersare made from a single piece of material. Preferably there are aplurality of shafts and each shaft comprises one reamer.

Another embodiment of the invention is directed to a wellbore drillingstring. The wellbore drilling string comprises a drill bit, a downholemud motor, a measurement-while-drilling (MWD) device relaying theorientation of the drill bit and the downhole mud motor to a controller,and a wellbore conditioning system. The wellbore conditioning systemcomprises at least one shaft and at least two eccentric unilateralreamer extending from the shaft. The unilateral reamers are positionedat a predetermined distance from each other and the unilateral reamersare positioned at a predetermined rotational angle from each other. Thewellbore conditioning system is positionable within the wellbore drillstring at a location in or around the bottom hole assembly.

Preferably, each unilateral reamer extends from an outer surface of theat least one shaft in a direction perpendicular to the axis of rotationof the at least one shaft. In the preferred embodiment, each reamer iscomprised of a plurality of blades, wherein each blade has a largerradius than a previous blade in the direction of counter rotation. Thewellbore conditioning system preferably further comprises a plurality ofcutters coupled to each blade. Each cutter is preferably aPolycrystalline Diamond Compact (PDC) cutter. The wellbore conditioningsystem preferably also further comprises at least one dome slidercoupled to each blade. Preferably, each dome slider is a PDC domeslider.

Preferably, there is a recess in the at least one shaft adjacent to eachreamer. In the preferred embodiment, the at least one shaft and reamersare made from a single piece of material. Preferably, there is aplurality of shafts and each shaft comprises one reamer.

Other embodiments and advantages of the invention are set forth in partin the description, which follows, and in part, may be obvious from thisdescription, or may be learned from the practice of the invention.

DESCRIPTION OF THE DRAWING

The invention is described in greater detail by way of example only andwith reference to the attached drawing, in which:

FIG. 1 is a schematic of an embodiment of the system of the invention.

FIGS. 2-4 are views of an embodiment of the reamers of the invention.

FIG. 5 is an exaggerated view of an embodiment of the system within awellbore.

DESCRIPTION OF THE INVENTION

As embodied and broadly described herein, the disclosures herein providedetailed embodiments of the invention. However, the disclosedembodiments are merely exemplary of the invention that may be embodiedin various and alternative forms. Therefore, there is no intent thatspecific structural and functional details should be limiting, butrather the intention is that they provide a basis for the claims and asa representative basis for teaching one skilled in the art to variouslyemploy the present invention

A problem in the art capable of being solved by the embodiments of thepresent invention is conditioning narrow wellbores without interferingwith the drilling devices. It has been surprisingly discovered thatpositioning a pair of unilateral reamers along a shaft allows forsuperior conditioning of narrow wellbores compared to existingtechnology.

FIG. 1 depicts a preferred embodiment of the wellbore conditioningsystem 100. In the preferred embodiment, wellbore condition system 100is comprised of a single shaft. However, in other embodiments, wellboreconditioning system 100 is comprised of leading shaft 105 a and trailingshaft 105 b, as shown in FIG. 1. While two shafts are shown, anothernumber of shafts can be used, for example, three or four shafts can beused. Preferably the total shaft length is ten feet, however the shaftcan have other lengths. For example, the total shaft length shaft can beeight feet or twelve feet in length. In embodiments with two shafts,shafts 105 a and 105 b are coupled at joint 110 (in FIG. 1, joint 110 isshown prior to coupling shafts 105 a and 105 b). In the preferredembodiment, joint 110 is a screw joint, wherein the male portion ofjoint 110 attached to shaft 105 b has exterior threads and the femaleportion of joint 110 attached to shaft 105 a has interior threads.However, another type of coupling can be used, for example the portionsof joint 110 depicted in FIG. 1 can be reversed with the male portion onshaft 105 a and the female portion on shaft 105 b. Furthermore, othermethods of joining shaft 105 a to shaft 105 b can be implemented, suchas welding, bolts, friction joints, and adhesive. In the preferredembodiment, upon being joined, shafts 105 a and 105 b are coaxial androtate in unison. Furthermore, in the preferred embodiment, joint 110may be more resistant to bending, breaking, or other failure than ifshafts 105 a and 105 b were a uni-body shaft.

In the preferred embodiment the shaft is comprised of steel, preferably4145 or 4140 steel alloys. However, the shaft can be made of other steelalloys, aluminum, carbon fiber, fiberglass, iron, titanium, tungsten,nylon, other high strength materials, or combinations thereof.Preferably, the shaft is milled out of a single piece of material,however other methods of creating the shaft can be used. For example,the shaft can be cast, rotomolded, made of multiple pieces, injectionmolded, and combinations thereof. The preferred outer diameter of theshaft is approximately 5.5 inches, however the shaft can have otherouter diameters (e.g. 10 inches, 20 inches, 30 inches, or anotherdiameter common to wellbores). As discussed herein, the reamers extendbeyond the outer diameter of the shaft.

As shown in FIG. 1, in the two shaft embodiment, each of shafts 105 aand 105 b has a single unilateral reamer 115 a and 115 b, respectively.In the uni-body shaft embodiment, the shaft has at least two unilateralreamers 115 a and 115 b. Each reamer 115 a and 115 b projects from thebody of the shaft on one, single side of the shaft. Furthermore, eachreamer 115 a and 115 b is preferably situated eccentrically on the bodyof shafts 105 a and 115 b such that the centers of mass of the reamers115 a and 115 b are not coaxial with the centers of mass of the body ofshafts 105 a and 115 b. As can be seen in FIG. 1, reamer 115 a projectsin a first direction (upwards on FIG. 1), while reamer 115 b projects ina second direction (downwards on FIG. 1). While reamers 115 a and 115 bare shown 180° apart from each other, there can be other rotationalconfigurations. For example, reamers 115 a and 115 b can be 90°, 45°, or75° apart from each other. In the preferred embodiment, reamers 115 aand 115 b are identical, however deviations in reamer configuration canbe made depending on the intended use of the system 100.

As shown in the embodiment of the system 100 depicted in FIG. 5, inoperation, the first reamer 115 a bores into one portion of the wellbore550 while the second reamer 115 b bores into a diametrically opposedportion of the wellbore 550. The opposing forces (shown by the arrows inFIG. 5) created by the diametrically opposed reamers centralize thesystem 100 within the wellbore 550. This self-centralizing featureallows system 100 to maintain a central location within wellbore 500while having no moving parts.

In the preferred embodiment each of reamers 115 a and 115 b has fourblades, however, there can be another number of blades (e.g., one blade,three blades, or five blades). Preferably, the radius of each of thefour blades projects from shafts 105 a and 105 b at a differentincrement. The incremental increase in the radius of the blades allowsthe first blade in the direction of counter rotation (i.e., the firstblade to contact the surface of the wellbore) to remove a first portionof the wellbore wall, the second blade in the direction of counterrotation to remove a second, greater portion of the wellbore wall, thethird blade in the direction of counter rotation to remove a third,greater portion of the wellbore wall, and the fourth blade in thedirection of counter rotation to remove a fourth, greater portion of thewellbore wall, so that, after the fourth blade, the wellbore is thedesired size. The progressing counter rotation blade radius layoutcreates an equalizing depth of cut. Cutter work load is evenlydistributed from blade to blade as the wellbore is being enlarged andconditioned. This calculated cutter work rate reduces impact loading.The reduction of impact loading translates into reduced torque andcutter fatigue. Furthermore, due to the gradual increase of the radiusof the blades, there is a smooth transition to full bore diameter, whichpreferably reduces vibration and torque on system 100.

As can be seen in FIGS. 2-4, each of the blades has a plurality ofcutters. Preferably, the cutters are Polycrystalline Diamond Compact(PDC) cutters. However, other materials, such as aluminum oxide, siliconcarbide, or cubic boron nitride can be used. Each of the cutters ispreferably 7/11 of an inch (16 mm) in diameter, however the cutters canhave other diameters (i.e., ½ an inch, ¾ of an inch, or ⅝ of an inch).The cutters are preferably replaceable and rotatable. In certainembodiments, the cutters have a beveled outer edge to prevent chippingand reduce the torque generated from the cutting structure. In apreferred embodiment, the blades have at least one dome slider 555, asshown in FIG. 5. Preferably, the dome slider 555 is made of the samematerial as the cutters. The dome slider 555 is preferably a rounded orsemi rounded surface that reduces friction with the wellbore wall whilethe system slides though the wellbore, thus protecting the cutters fromdamage. The dome sliders 555 contact the surface of the wellbore 550wall or casing and create a standoff of the reamer blade which aids inthe ability of the system 100 to slide through the wellbore 550 when thedrill string is not in rotation. Additionally, during operation ofsystem 100, dome sliders 555 allow the system to rotate within wellbore550 with less friction than without the dome sliders, thereby decreasingthe torque needed to rotate the system and reducing the damage to thecasing and the cutting structure of the tool during the trippingoperation. Furthermore, as the system 100 slides through or rotateswithin a casing, the dome sliders 555 protect the casings from thecutters.

Returning to FIG. 1, disposed on either side of each of reamers 115 aand 115 b are preferably recesses 120 a and 120 b. Recesses 120 a and120 b have a smaller diameter than the body of shafts 105 a and 105 b.Preferably, recesses 120 a and 120 b facilitate debris removal whilesystem 100 is conditioning. Furthermore, recesses 120 a and 120 b mayincrease the ease of milling reamers 115 a and 115 b.

Reamers 115 a and 115 b are preferably disposed along the shaft at apredetermined distance apart. For example, the reamers can be 4 feet, 5feet, 6 feet, or another distance apart. The distance between reamers115 a and 115 b as well as the rotational angle of reamers 115 a and 115b can be optimized based on the characteristics (e.g., the desireddiameter and curvature) of the wellbore. The further apart, both indistance and rotation angle, the two reamers are positioned, thenarrower the wellbore system 100 can drift through. The outer reamerbody diameter plays a critical part in the performance of system 100.Furthermore, having adjustable positioning of the reamers 115 a and 115b allows system 100 to achieve multiple pass-thru/drift requirementsusing the single tool.

Preferably, system 100 is positioned at a predetermined location up-holefrom the directional bottom-hole assembly. The directional bottom-holeassembly may included, for example, the drill bit, bit sub, downhole mudmotor (e.g. a bent housing motor), and a measurement-while-drillingdevice, drill collars, a directional control device, and other drillingdevices. By placing the wellbore conditioning system in or around thebottom hole assembly of the drill string, the reaming tool will havelittle to no adverse affect on the ability to steer the directionalassembly or on the rate of penetration, and can achieve the desiredbuild or drop rates.

Other embodiments and uses of the invention will be apparent to thoseskilled in the art from consideration of the specification and practiceof the invention disclosed herein. All references cited herein,including all publications, U.S. and foreign patents and patentapplications, are specifically and entirely incorporated by reference.It is intended that the specification and examples be consideredexemplary only with the true scope and spirit of the invention indicatedby the following claims. Furthermore, the term “comprising of” includesthe terms “consisting of” and “consisting essentially of.”

1.-20. (canceled)
 21. An apparatus for use on a drill string forincreasing the drift diameter of a well bore during drilling,comprising: at least one eccentric reamer positioned on the drillstring, wherein each reamer has a plurality of cutting blades extendinga distance radially outwardly from the outer surface of the reamer,wherein a first cutting blade extends a first distance and, in an ordercounter to the direction of rotation, each additional cutting bladeextends an equal or greater distance than the preceding cutting blade,and the plurality of blades defining a curved cutting area extendingapproximately 50% or less of the circumference of each reamer.
 22. Theapparatus of claim 21, further comprising grooves disposed between thecutting blades.
 23. The apparatus of claim 21, wherein each set ofcutting blades is arranged along a spiral path along the surface of theassociated reamer.
 24. The apparatus of claim 21, further comprising anarray of two or more cutting teeth extending from each of the cuttingblades and tangentially to each reamer.
 25. The apparatus of claim 24,wherein the teeth of each of the plurality of cutting blades of eachreamer are offset from the teeth of the adjacent cutting blades.
 26. Theapparatus of claim 24, wherein each tooth is comprised of carbide ordiamond.
 27. The apparatus of claim 24, wherein the teeth face thedirection of rotation.
 28. The apparatus of claim 21, further comprisinga coupling adapted to receive a bottom hole assembly.
 29. The apparatusof claim 21, wherein the apparatus is positioned behind a drill bit. 30.The apparatus of claim 29, wherein the apparatus is positioned at least100 feet behind the drill bit.
 31. The apparatus of claim 24, whereinthe teeth of each of the plurality of cutting blades are longitudinallyoverlapping from the teeth of the adjacent cutting blades.
 32. A wellbore drilling device, comprising: a drill string; a drill bit positionedat the end of the drill string; and at least one eccentric reamerpositioned on the drill string, wherein each reamer has a plurality ofcutting blades extending a distance radially outwardly from the outersurface of the reamer, wherein a first cutting blade extends a firstdistance and, in an order counter to the direction of rotation, eachadditional cutting blade extends an equal or greater distance than thepreceding cutting blade, and the plurality of blades defining a curvedcutting area extending approximately 50% or less of the circumference ofeach reamer.
 33. The device of claim 32, further comprising groovesdisposed between the cutting blades.
 34. The device of claim 32, whereineach set of cutting blades is arranged along a spiral path along thesurface of the associated reamer.
 35. The device of claim 32, furthercomprising an array of two or more cutting teeth extending from each ofthe cutting blades and tangentially to each reamer.
 36. The apparatus ofclaim 35, wherein the teeth of each of the plurality of cutting bladesof each reamer are offset from the teeth of the adjacent cutting blades.37. The apparatus of claim 35, wherein each tooth is comprised ofcarbide or diamond.
 38. The apparatus of claim 35, wherein the teethface the direction of rotation.
 39. The apparatus of claim 32, whereinthe pair of similar eccentric reamers are positioned at least 100 feetbehind the drill bit.
 40. The apparatus of claim 35, wherein the teethof each of the plurality of cutting blades are longitudinallyoverlapping from the teeth of the adjacent cutting blades.
 41. Anapparatus for use on a drill string for increasing the drift diameter ofa well bore during drilling, comprising: a pair of similar eccentricreamers positioned opposingly on the drill string, wherein each reamerhas a plurality of cutting blades extending a distance radiallyoutwardly from the outer surface of the reamer, wherein a first cuttingblade extends a first distance and, in an order counter to the directionof rotation, each additional cutting blade extends an equal or greaterdistance than the preceding cutting blade, and the plurality of bladesdefining a curved cutting area extending approximately 50% or less ofthe circumference of each reamer.
 42. The apparatus of claim 41, furthercomprising grooves disposed between the cutting blades.
 43. Theapparatus of claim 41, wherein each set of cutting blades is arrangedalong a spiral path along the surface of the associated reamer.
 44. Theapparatus of claim 41, further comprising an array of two or morecutting teeth extending from each of the cutting blades and tangentiallyto each reamer.
 45. The apparatus of claim 44, wherein the teeth of eachof the plurality of cutting blades of each reamer are offset from theteeth of the adjacent cutting blades.
 46. The apparatus of claim 44,wherein each tooth is comprised of carbide or diamond.
 47. The apparatusof claim 44, wherein the teeth face the direction of rotation.
 48. Theapparatus of claim 41, further comprising a coupling adapted to receivea bottom hole assembly.
 49. The apparatus of claim 41, wherein theapparatus is positioned behind a drill bit.
 50. The apparatus of claim49, wherein the apparatus is positioned at least 100 feet behind thedrill bit.
 51. The apparatus of claim 44, wherein the teeth of each ofthe plurality of cutting blades are longitudinally overlapping from theteeth of the adjacent cutting blades.
 52. A well bore drilling device,comprising: a drill string; a drill bit positioned at the end of thedrill string; and a pair of similar eccentric reamers positionedopposingly on the drill string, wherein each reamer has a plurality ofcutting blades extending a distance radially outwardly from the outersurface of the reamer, wherein a first cutting blade extends a firstdistance and, in an order counter to the direction of rotation, eachadditional cutting blade extends an equal or greater distance than thepreceding cutting blade, and the plurality of blades defining a curvedcutting area extending approximately 50% or less of the circumference ofeach reamer.
 53. The device of claim 52, further comprising groovesdisposed between the cutting blades.
 54. The device of claim 52, whereineach set of cutting blades is arranged along a spiral path along thesurface of the associated reamer.
 55. The device of claim 52, furthercomprising an array of two or more cutting teeth extending from each ofthe cutting blades and tangentially to each reamer.
 56. The apparatus ofclaim 55, wherein the teeth of each of the plurality of cutting bladesof each reamer are offset from the teeth of the adjacent cutting blades.57. The apparatus of claim 55, wherein each tooth is comprised ofcarbide or diamond.
 58. The apparatus of claim 55, wherein the teethface the direction of rotation.
 59. The apparatus of claim 52, whereinthe pair of similar eccentric reamers are positioned at least 100 feetbehind the drill bit.
 60. The apparatus of claim 55, wherein the teethof each of the plurality of cutting blades are longitudinallyoverlapping from the teeth of the adjacent cutting blades.